Subterranean drilling typically involves rotating a drill bit from the surface or on a downhole motor at the remote end of a tubular drill string. It involves pumping a fluid down the inside of the tubular drill string, through the drill bit, and circulating this fluid continuously back to the surface via the drilled space between the hole/tubular, referred to as the annulus. This pumping mechanism is provided by positive displacement pumps, also referred to as mud pumps, that are connected to a manifold which connects to the drill string, and the rate of flow into the drill string depends on the speed of these pumps.
For a subsea wellbore, a tubular, known as a riser, extends from the rig at the water's surface to the top of the wellbore, which exists at subsea level on the ocean floor. It provides a continuous pathway for the drill string and the fluids emanating from the wellbore below the seabed. In effect, the riser extends the wellbore from the sea bed to the rig, and thus the total wellbore annulus also includes the annular volume of the riser.
Conventionally, the wellbore is open to atmospheric pressure and there is no surface applied pressure or other pressure existing in the system. The drill pipe rotates freely without any sealing elements imposed or acting on the drill pipe at the surface or subsea. There is no requirement to divert the return fluid flow or exert pressure on the system during these standard operations.
The bit penetrates its way through layers of underground formations until it reaches target prospects, i.e., rocks which contain hydrocarbons at a given temperature and pressure. These hydrocarbons are contained within the pore space of the rock (i.e., the void space) and can contain water, oil, and gas constituents, also referred to as reservoirs. Due to overburden forces from layers of rock above, these reservoir fluids are contained and trapped within the pore space at a known or unknown pressure, referred to as pore pressure. An unplanned inflow of these reservoir fluids is well known in the art, and is referred to as a formation influx or kick. An uncontrolled kick is referred to as a blow out event.
A fluid of a given density, also referred to as weight, fills and circulates the annulus of the drilled hole. The purpose of this drilling fluid/mud is to lubricate, carry drilled rock cuttings to surface, cool the drill bit, and power the downhole motor and other tools. Mud is a very broad term and in this context it is used to describe any fluid or fluid mixture that covers a broad spectrum from air, nitrogen, misted fluids in air or nitrogen, foamed fluids with air or nitrogen, aerated or nitrified fluids, to heavily weighted mixtures of oil and water with solids particles.
Most importantly, this fluid and its resulting hydrostatic pressure, defined as the pressure column of fluid exerts at the bottom of the hole from its given density and true vertical height, prevents the reservoir fluids at their existing pore pressure from entering the drilled annulus. The resultant bottom hole pressure (BHP) at the well bottom or at a given depth in the wellbore using this relationship between density and true vertical height of the drilling fluid system is the primarily method used for controlling the BHP to prevent an influx event from occurring in conventional drilling.
The bottom hole pressure (BHP) exerted by the hydrostatic pressure of the drilling fluid is therefore the primary barrier for preventing an influx from the formation.
BHP can be expressed in terms of static BHP or dynamic/circulating BHP. Static BHP relates to the BHP value when the mud pumps are not in operation (i.e., no circulation). Dynamic or circulating BHP refers to the BHP value when the pumps are in operation during drilling or circulating.
The drilling fluid must thus also exert a pressure less than the fracture pressure of the formation, the fracture pressure being where fluid will be forced into the rock as a result of pressure in the wellbore exceeding the formation's horizontal stress forces/matrix strength, leading to a failing or breakdown of the formation rock. Exceeding the formation fracture pressure causes the formation to fracture and the expensive drilling fluid to be lost as it flows outwards into the formation. The increased concentration of solids or drilled cuttings in the drilling fluid will result in an increase in density above the normal static mud weight, which could drive the BHP above the fracture pressure.
Depending on the magnitude of any incurred losses, as fluid is lost/flows outwards into the formation, there is high risk that the consequent decrease in the hydrostatic pressure in the well resulting from the decreasing fluid level height in the wellbore decreases the BHP to below the formation pressure. This undesired condition results in formation influx, described herein. These conditions are well known in the art, and are also referred to as losses (minor, major, and total/severe depending on the magnitude) or lost circulation.
Increased solids from drilling and the hydrostatic pressure of the column of fluid in the riser can reduce the amount of hole that can be drilled before having to set an additional casing string, depending on the existing fracture pressures. The solids can affect the rate of circulation, crating limits due to pressure and thus affects the ability to also clean the hole effectively. The extended riser height above the wellbore and the additional hydrostatic pressure becomes more pronounced as water depth increases. These conditions are amplified in deep and ultra-deep water wellbores, where the difference between fracture pressures in the shallow sections of the well and the pore pressures of the deeper sections is quite narrow compared to onshore wells. Therefore, to drill this type of deep water wellbore, the ECD must be reduced or controlled, and may mean the difference between incurring time and cost associated with setting an additional casing string to safely mitigate the problem.
Equivalent circulating density (ECD) is the increase in bottom hole pressure (BHP) expressed as an increase in pressure that occurs only when drilling fluid is being circulated. This pressure is different than the hydrostatic pressure as the ECD value reflects the total friction losses over the entire length of the wellbore annulus, from the point of fluid exiting the bit at the wellbore bottom to where it exits the return flow line at surface. The ECD can result in a bottom hole pressure during circulating/drilling that varies from slightly to significantly higher values when compared to static conditions (i.e., no circulation). The ECD is related to the circulating or drilling BHP in the sense that the ECD is calculated from the circulating/drilling BHP. The ECD value can increase with an increasing concentration of drilled solids/cuttings produced during the drilling of any formation and any increases in the mud viscosity properties during drilling, which can force the BHP above the fracture pressure. A high ECD thus poses a high risk in exceeding formation fracture pressures, with consequences described herein.
The goal of a conventional drilling system is therefore to maintain the BHP above the pore pressure but below the fracture pressure. The management of BHP can be referred to as managed pressure drilling (MPD) or ECD management.
As drilling progresses, pipe must be connected to the existing drill string to drill deeper. Conventionally, this involves shutting down fluid circulation completely so the pipe can be connected into place as the top drive must be disengaged.
During connection operations, the bottom hole pressure is largely affected, decreasing in value which can lead to a multitude of events such as influx, described herein, and cuttings drop out. On deeper wells, undesired large variances in the drilling fluid properties are created from high bottom hole temperatures when static flow conditions exist over a connection or other non-circulation period.
U.S. Pat. Nos. 6,527,054, 6,648,081, 6,854,532, 6,981,561, 7,114,581 7,270,185 describe the control of ECD.
In U.S. Pat. No. 7,270,185, the equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in the returning fluid path of a riser utilizing an active differential pressure device, such as a centrifugal pump or turbine, located adjacent to the riser. The fluid is then returned into the riser above the restriction. The active differential pressure device is in the riser, outside the riser, or in an annulus of the wellbore. It is 1000 feet below the sea level to the sea bottom. It is a centrifugal pump, turbine, jet pump, or positive displacement pump. It controls equivalent circulating density of the drilling fluid in at least a portion of the fluid circuit.
In U.S. Pat. No 7,14,581 and U.S. Pat. No. 6,981,561, the bottom hole pressure and hence the equivalent circulating density is controlled by crating a pressure differential at a selected location in the return fluid path with an active pressure differential device to reduce or control the bottom hole pressure.
In U.S. Pat. No. 7,114,581, the subsea wellbore drilling system comprises an adjustable pump system in fluid contact with the annulus for regulating the fluid pressure at the bottom of the borehole at predetermined values during downhole operations in the wellbore to overcome at least a portion of the hydrostatic pressure and friction loss pressures of the return fluid.
In U.S. Pat. No. 6,981,561, the drilling system comprises a seal between the active differential pressure device and a drive assembly.
In U.S. Pat. Nos. 6,648,081 and 6,854,532, an adjustable pump is provided which is coupled to the annulus of the well. The lift provided by the adjustable pup effectively lowers the bottom hole pressure. The system described in U.S. Pat. No. 6,854,532 further comprises a flow control device in the subsea fluid circulation system. The control device is a remotely actuated choke for maintaining positive pressure of the fluid at the surface.
As mentioned above, these systems are large in magnitude, and must be installed through the side entry points of the moon pool area on an offshore installation. This increases installation time, complexity, operational safety risks at installation, and ultimately well costs due to the extended time periods during installation and removal.
A continuous circulation method has been developed by the applicant to achieve constant circulation through a side bore in the pipe at surface before the top drive is disengaged for a connection. Continuous circulation counteracts the negative effects on BHP associated with connections, it is therefore a critical process for managing and controlling BHP during connections. A description of one specific design for continuous circulation is described in U.S. Pat. No. 2,158,356.
The use of blow out preventers, referred to as BOP's, to seal and control the formation influxes, described herein, in the wellbore are well known in the art and are compulsory pressure safety equipment used on both land and offshore rigs. Whilst land and subsea BOP's (SSBOP) are generally secured to a sell head at the top of a wellbore, BOPs on offshore rigs are generally mounted below the rig deck and/or integrated into the bottom of the riser system on the ocean floor connected to the top of the wellbore.
On offshore rigs, a high pressure riser booster flow line connects a high pressure pump, referred to as the riser booster pump and identical in operation to a rig mud pump, to an inlet point (s) on the riser. These are normally located near the bottom of the riser above the subsea BOP to allow circulation of the entire riser volume/annulus over its entire length to surface. The riser booster flow line runs externally along the entire length of the riser system within a common rail. This system is used to generally increase the flow rate of fluid inside the riser for lifting cuttings in the large diameter riser conduit during drilling operations, but can also be used to circulate a gas influx from the riser volume and thus is partial to both the drilling and well control systems on the rig.
The annular BOP elements seal around the drill string, thus closing the annulus and stopping flow of fluid from the wellbore. They typically include a large flexible rubber or elastomer packing unit configured to seal around a variety of drill string sizes when activated, and are not designed to be actuated during drill string rotation as this rapidly wears or damages the sealing element.
A pressurized hydraulic fluid and piston assembly are used to provide the necessary closing pressure of the sealing element on the drill string. These closing times are typically slower due the large volume of power fluid that must be pressurized to operate the piston at a subsea depth.
WO 2013/135725 describes a new technology, a modified annular preventer, termed the Quick Closing Annular (QCA), which can rapidly seal the riser at a fraction of the closing time when compared to a standard annular. The inclusion of a QCA in the riser configuration therefore enhances both riser pressure control and well control, as its position isolates the pressure limiting component, the rig's slip joint, located at the riser top. However, it is not a necessary component for the inventive system and method, and can be substituted by a standard subsea annular.
Managed pressure drilling (MPD) utilizes additional special equipment that has been developed to keep the well closed at all times, as the wellhead pressures in these cases are non-atmospheric when compared to the traditional art of the conventional overbalanced drilling method, described herein. These thus operate as pressurized closed loop systems.
The closed loop is generated by a pressure seal around the drill pipe at surface or deeper in the riser configuration with a pressure containment device. Flow is diverted to a flow line by this device, referred to as a rotating control head (RCD or RCH), pressure control while drilling (PCWD), or rotating blow out preventer (RBOP), attached to a flow spool side outlet in the riser below the sealing point. The function of the rotating pressure containment device is to allow the drill string and its tool joints to pass through its sealing mechanism with reciprocation/stripping or rotation while maintaining pressure integrity around the tubular. With drilling activity in progress and the device closed, a back pressure is created on the annulus. The drill string is stripped or rotated through the sealing element (s) of the pressure containment device which isolates the pressurized annulus from the external atmosphere. With these devices, the sealing element rotates with the drill string while maintaining the pressure integrity of the seal. The rotation is handled by a bearing which may be a thrust, roller, cone or ball bearings or a combination of these which requires an internal bearing and seals prone to mechanical failure from the imposed loads of drilling. All are standard equipment and are commercially available with existing designs on the market. These are described in detail in U.S. Pat. Nos. 7,699,109, 7,926,560, and 6,129,152.
The applicant has also developed an alternative apparatus to the RCD technology, utilizing a non-rotating sealing device referred to as the Riser Drilling Device RDD, described in WO 2012/127227 and WO 2011/128690. This eliminates the requirement for a bearing assembly, with a single or dual seal sleeve assembly installed within a specified housing within the riser system and secured in place with hydraulically locking dogs/pistons. Rotation of the seal sleeve assembly with the drill pipe is prevented through the frictional forces of an adjacent annular packer assembly within the housing which applies pressure to the external surface of the seal sleeve when it is in position in the housing. The seal sleeve's mechanical structure and composite materials result in a high wear resistant low friction sealing face on the drill pipe. This system does not use the conventional bearing systems described in the prior art.
Complexity increases when MPD techniques are applied offshore, and specifically the deeper the water the more difficult these operations become. The riser section from the seabed floor to the drilling platform becomes an extension of the wellbore; as water depth increases the riser length increases accordingly, which increases the hydrostatic pressure and ECD effects exerted on the wellbore below, described herein.
The conditions described herein result in a narrow operating envelope for drilling, also referred to as a narrow drilling margin, and is defined as the small circulating/drilling BHP “window” resulting from the upper and lower constraints of lower fracture pressures and higher pore pressures at a total depth in the wellbore. The result is constraints in the flexibility within the circulating BHP during drilling and/or connections, posing challengers with even the most current and refined drilling methods.
A riser margin is additionally a safety factor desired in any offshore floating installation drilling operation. However, this cannot always be achieved given the water depth and formation pore and fracture pressures that are present for the well. A riser margin means that if the riser is disconnected, for example, in an emergency situation, the hydrostatic pressure from the drilling mud in the borehole and the seawater pressure above the seabed/subsea BOP is sufficient to maintain an overbalance against the formation pore pressure in the wellbore. A method which can allow a higher density drilling mud to be used below the subsea BOP would therefore increase the riser margin potential, and would thus be beneficial to the safety of the operation.
A deeper subsea set riser sealing solution for MPD using the RDD allows enhanced pressure and ECD control over the wellbore given its predetermined point of installation. It will allow the riser to be isolated so that the extended column of fluid above the sealing point can be isolated, eliminating its hydrostatic effects on the drilling annulus below, while allowing drilling to be performed (rotation and reciprocation) through the non-rotating sealing point. The deeper the set depth of the RDD, the higher the degree of controllability of the BHP results through the ECD, which is offset through isolating the hydrostatic pressure above its sealing point from the fluid column in the riser.
An active pressure differential device, such as a turbine, centrifugal pump or turbine, is disclosed in U.S. Pat. No. 7,114,581, and alters the pressure below in the wellbore to offset the ECD during drilling and circulating. The pump is either mounted within the drill string and moves in the wellbore with the drill string, or is alternatively attached to the wellbore and remains stationary relative to the drill string. An annular seal disposed around the active pressure differential device causes the return flow to flow into the pump suction. As the pump draws the fluid into its suction, it creates a differential pressure across the pump and draws down the wellbore pressure.
There have been many approaches in the attempt to find a safe and effective solution for drilling these challenging wells using riser pumping methods. Some of the more current concepts and technologies present today are AGR's EC-Drill system, Ocean Riser System's Lower Riser Return system (LRRS), and Deep Vision's Delta Vision system. These approaches are deemed “mid riser pumping” solutions, and are described below.
A dual gradient approach is described in detail in U.S. Pat. Nos. 6,415,877, 6,648,081, and 6,854,532, utilizing a subsea submersible centrifugal pump system. One embodiment of this application describes a riser-less system wherein a centrifugal pump connected to a separate return line controls the fluid flow to the surface, and in doing so counteracts the ECD effects during circulation. In this embodiment, the centrifugal pump is a standalone module connected to the returns annulus.
Another embodiment shows the submersible pump system mounted and fastened to a side outlet on a modified riser joint. A flow line extends from the outlet of the pump to the floating installation at the surface. During drilling and circulation, wellbore ECD is counteracted by energizing the pump and drawing the drilling fluid from the riser annulus and returning it to the surface. This in turn varies the fluid level height in the riser, and the submersible pump operates in conjunction with the rig drilling pump rate to maintain the required fluid height in the riser during drilling. The degree that the fluid height in the riser is increased or decreased (and its subsequent hydrostatic pressure variance) is equivalent to the ECD offset value desired for the well. During drilling, the pump decreases the fluid height in the riser and maintains it at a level where the decreased hydrostatic pressure is equivalent to the ECD value during circulation. During connections in absence of continuous circulation, the submersible pump is ramped down and the riser is filled to a level so that the pore pressure is balanced during the connection's static periods.
Additionally with this system, an optional delivery system may continuously inject a lighter density fluid than that of the mud weight being used into the returning fluid stream within the riser at a rate which can be controlled to provide a secondary regulation of the wellbore pressure.
With this system the BHP can be adjusted over minutes, versus the hours which would be undertaken to change the well over to a lighter mud weight. It also allows a heavier drilling mud to be used in the wellbore as a result of a reduced hydrostatic pressure above in the riser system from a reduced fluid level height (hence “dual gradient”), which will enhance hole cleaning and lubrication in the wellbore. This also may or may not create a sufficient riser margin for the well, depending on the formation pressures and water depth.
However, this system utilizes an inefficient pump technology for drawing fluid from the riser which may contain large solids particles. Centrifugal pumps operate at low efficiency in such operating conditions, and the big gaps in the blades of the impeller of the pump result in pump efficiencies of approximately 50%. The power requirements and mechanical size of the pump therefore increase to make up for this low efficiency to satisfy the fluid flow rate requirements, and results in a large dimensional footprint of the equipment, installation complexities, and large power requirements for its operation. This system also requires installation below the rotary table from the side of the moon pool which increases safety risks, time, and complexity during rig up.
The riser volume above the liquid level during operation of these systems is open to the atmosphere and thus kept at atmospheric conditions. Any gas escaping from the drilling fluid that may be entrained releases in the riser and migrates towards the atmospheric pressure above. Gas separation therefore occurs within the upper riser volume, and depending on the volume of gas breakout, it may be necessary to close in the surface diverter to prevent gas release to the surrounding atmosphere on the rig floor. Risk is thus involved with this method.
A large air gap may furthermore exist in the riser above the varied fluid level, along with an absence of a riser sealing device with this system, so that many operators deem such conditions unsafe. Decreasing the hydrostatic pressure/fluid level in the riser without a device in place to seal off the riser in an emergency is risky, and such conditions yield the potential for undesirable events to unfold.
Another dual gradient approach, described in detail in WO 2010/095947, describes similar design features and advantages as the previous system, with the exception that it incorporates a rotating sealing device around the drill pipe at surface or a surface BOP to seal off the riser. This gives the disclosed system an added safety contingency, sealing off the riser as the fluid level within the riser is decreased and providing a safety barrier which contains any gas breaking out from the drilling fluid. In an embodiment, it utilizes an independent return line from the outlet of the subsea pump attached to the riser which adjusts the fluid level within the riser and regulates the bottom hole pressure (BHP) of the wellbore. It operates with the same principle, moving towards the use of a heavier mud weight in the drilling annulus while using the submersible pump to control the fluid level of a lighter density fluid in the riser to offset the ECD of the well. The pump rate is controllable to regulate the interface between the two separate fluids at a consistent height in the riser, with the maximum pressure adjustment achievable being the fluid level between the rotating sealing device at surface and the inlet to the submersible pump.
A further progression and improvement to existing Lower Riser Return Systems (LRRS) is described in WO 2009/123476, which incorporates the use of an “annular seal” around the drill pipe at surface or at a subsea point within the riser during drill pipe connections. This is to compensate for the reduction in wellbore pressure when the injection into the drill pipe ceases, thus eliminating the ECD from the BHP. However, during drilling, the annular seal remains open with the option of installing a wiper or stripper element in the diverter to prevent any gas breakout escaping to the rig floor atmosphere. In addition to the annular sealing device, the disclosed system utilizes an independent return line from the outlet of the subsea pump attached to the riser fitted with a subsea gas liquid separator and subsea choke valve assembly to safely handle the removal of gas from the return fluid flow stream and venting this to the surface while regulating dynamically the annular pressure in the well. It operates within the same principle of dual gradient fluids, using the submersible pump to control the fluid level of a lighter density fluid in the riser to compensate for the ECD of the well. The installation and operation becomes more complex with this system with the increased amount of subsea equipment, with many of the same deficiencies as the systems described herein.
Yet another improved approach to pumped riser methods is described in U.S. Pat. No. 7,270,185 B2. The ECD is here controlled by the diversion of the return fluid flow from the wellbore around a deeper set subsea flow restriction, such as a rotary seal, set within the riser utilizing an “active differential pressure device”, such as a centrifugal pump or turbine, to offset the ECD and adjust the BHP. The pump or turbine is located adjacent to the riser and is connected to a modified riser joint to a flow outlet existing below the sealing device, and reconnects with the riser directly above the sealing device. In an alternate embodiment, the outlet line below the sealing device does not reconnect with the riser, but connects to the floating installation at surface through a separate return flow line.
The centrifugal pump creates a pressure differential in the returning fluid as it draws fluid into its suction inlet from riser annulus below and discharges it into the riser annulus above the sealing device, with the amount of differential pressure across the pump regulated to the value of ECD offset desired for the wellbore. The submersible pump is mounted on a riser joint and installed within the riser configuration. The depth of the submersible pump and sealing device depends on the maximum desired reduction in the ECD. With this concept, there still remains the issue of a single submersible pump and return line, and therefore it lacks contingency for failures within the system, such as solids plugging of the pump or pump failure. The concept, however, addresses the issues of the ability to seal off the riser with the inclusion of a “rotary sealing device” which contains any gas breakout that may occur in the upper riser volume.
The well is also drilled with a relatively full fluid column present in the riser above the sealing point. The “sealing device” remains closed throughout operations and isolates the hydrostatic effects from the fluid in the riser section above it. The energized submersible pump continues to return fluid to the riser above, pumping fluid from below the sealing device and returning it to the riser annulus above the sealing device in an attempt to counteract ECD during drilling and circulation.
Further variations of the systems described herein are described in WO 2012/003101, WO 2005/052307, WO 2011/058031, and U.S. Pat. Nos. 7,264,058, 7,958,948, and 7,913,764.